Oil sand, as known in the Athabasca region of Alberta, Canada, comprises water-wet, coarse sand grains having flecks of a viscous hydrocarbon, known as bitumen, trapped between the sand grains. The water sheaths surrounding the sand grains contain very fine clay particles. Thus, a sample of oil sand, for example, might comprise 70% by weight sand, 14% fines, 5% water and 11% bitumen. (All % values stated in this specification are to be understood to be % by weight.) The bitumen recovered from Athabasca oil sand is generally very viscous and has an API gravity of less than 10 due to the large amount of heavy ends, such as residue and asphaltenes.
For the past 25 years, the bitumen in Athabasca oil sand has been commercially recovered using a water-based process. In the first step of this process, the oil sand is slurried with process water, naturally entrained air and, optionally, caustic (NaOH). The slurry is mixed, for example in a tumbler or pipeline, for a prescribed retention time, to initiate a preliminary separation or dispersal of the bitumen and solids and to induce air bubbles to contact and aerate the bitumen. This step is referred to as “conditioning”.
The conditioned slurry is then further diluted with flood water and introduced into a large, open-topped, conical-bottomed, cylindrical vessel (termed a primary separation vessel or “PSV”). The diluted slurry is retained in the PSV under quiescent conditions for a prescribed retention period. During this period, aerated bitumen rises and forms a froth layer, which overflows the top lip of the vessel and is conveyed away in a launder. Sand grains sink and are concentrated in the conical bottom. They leave the bottom of the vessel as a wet tailings stream containing a small amount of bitumen. Middlings, a watery mixture containing solids and bitumen, extend between the froth and sand layers.
The wet tailings and middlings are separately withdrawn, combined and sent to a secondary flotation process. This secondary flotation process is commonly carried out in a deep cone vessel wherein air is sparged into the vessel to assist with flotation. This vessel is referred to as the TOR vessel. The bitumen recovered by flotation in the TOR vessel is recycled to the PSV. The middlings from the deep cone vessel are further processed in induced air flotation cells to recover contained bitumen.
The froths produced by the PSV and flotation cells are then combined and subjected to further froth cleaning, i.e., removal of entrained water and solids, prior to upgrading. Typically, bitumen froth comprises about 60% bitumen, 30% water and 10% solids. It is understood, however, that these values can vary depending upon the grade (e.g., bitumen content and/or fines content) of the mined oil sand ore. There are currently two commercially proven processes to clean bitumen froth. One process involves dilution of the bitumen froth with a naphtha solvent, followed by bitumen separation in a sequence of scroll and disc centrifuges. Alternatively, the naphtha diluted bitumen may be subjected to gravity separation in a series of inclined plate separators (“IPS”) in conjunction with countercurrent solvent extraction using added naphtha, or some combination of both.
While the hydrocarbon recovery is very high when using naphtha dilution (˜98%), there remains an undesirable amount of contaminants in the product bitumen comprised of mostly solids and water (e.g., 1% and 2%, respectively) and asphaltenes. It is understood that these values can vary depending upon the quality of the bitumen froth. These contaminants contained therein pose a risk to the downstream upgrading operation; the chlorides in the residual water present a corrosion risk to processing equipment while the solids and asphaltenes foul the upgrading equipment and reduce catalyst life. Thus, the majority of the bitumen product must first be upgraded using fluid coking units. The requirement to thermally crack the majority of this product stream comes with additional drawbacks in the last phase of the upgrading process (e.g., hydrotreating/hydroprocessing); the thermally cracked coker products now require significantly higher catalyst addition rates due to fouling of the catalyst active sites, hydrotreating intensity requirements are much higher for cracked product streams and more hydrogen per barrel of feed is required to complete the final upgrading step. Finally, the conventional froth treatment naphtha process produces Fluid Fine Tailings (FFT), which is difficult to reclaim, and has significant losses of solvent (naphtha) to the tailings pond.
The other commercial process involves diluting the bitumen froth with a paraffinic solvent, for instance a mixture of iso-pentane and n-pentane, followed by gravity separation. When paraffinic solvent is used, a portion of the asphaltenes in the bitumen is also rejected by design, thus achieving solid and water levels that are lower than those in the naphtha-based froth treatment. Thus, some of the product streams by-pass the fluid coker primary upgrading step. Also, a moderate reduction in hydrotreating intensity would be expected in processing partially DAO product streams.
However, with the paraffinic process there is a much lower hydrocarbon recovery (˜92%), with significant losses of volatile solvent (pentane) to tailings. The process also produces FFT, which, as mentioned, is difficult to reclaim.